e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2006


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ......... to ..........

Commission File Number 1-7584

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		74-1079400
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

2800 Post Oak Boulevard
P. O. Box 1396
Houston, Texas		77251
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code (713) 215-2000

None
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

The number of shares of Common Stock, par value $1.00 per share, outstanding as of April 30, 2006 was 100.

REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS H (1)(a) AND (b) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM 10-Q WITH THE REDUCED DISCLOSURE FORMAT.

EXPLANATORY NOTE

On February 28, 2006, we concluded that our consolidated financial statements for the years ending December 31, 2004 and 2003 should be restated to correct an error related to the methodology used to calculate the average cost of our natural gas inventory. We believe the impact of the adjustment is not material to any of the previously issued consolidated financial statements. However, the cumulative adjustment required to correct the error was significant to the Consolidated Statement of Income for 2005. In connection with the restatement required by the natural gas inventory adjustment, the consolidated financial statements for the years ending December 31, 2004 and 2003 were also restated to record the effects of certain other prior period adjustments.

As we have determined that the quarterly financial information included in our Quarterly Reports on Forms 10-Q and 10 Q/A filed in 2005 were not materially misstated and can be relied upon, we will not be amending those filings.

For a discussion of additional information on the restatement, along with restated financial statements for the three months ending March 31, 2005, see “Part I. Financial Information: Item 1. Financial Statements – Notes to Condensed Consolidated Financial Statements – 2. Restatement.”

TRANSCONTINENTAL GAS PIPE LINE CORPORATION
INDEX


	Page
PART I. FINANCIAL INFORMATION:

Item 1. Financial Statements —

Condensed Consolidated Statement of Income for the three months ended March 31, 2006 and 2005		4

Condensed Consolidated Balance Sheet as of March 31, 2006 and December 31, 2005		5

Condensed Consolidated Statement of Cash Flows for the three months ended March 31, 2006 and 2005		7

Notes to Condensed Consolidated Financial Statements		8

Item 2. Management’s Narrative Analysis of the Results of Operations		23

Item 4. Controls and Procedures		28

PART II. OTHER INFORMATION		30

Item 1. Legal Proceedings.		30

Item 1A. Risk Factors.		30

Item 5. Other Information.		30

Item 6. Exhibits		31
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906

Certain matters discussed in this report, excluding historical information, include forward-looking statements – statements that discuss our expected future results based on current and pending business operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

Forward-looking statements can be identified by words such as “anticipates,” “believes,” “expects,” “planned,” “scheduled,” “could,” “continues,” “estimates,” “forecasts,” “might,” “potential,” “projects” or similar expressions. Although we believe these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks that may cause future results to be materially different from the results stated or implied in this document. Additional information about issues that could cause actual results to differ materially from forward-looking statements is contained in our 2005 Annual Report on Form 10-K.

PART 1 — FINANCIAL INFORMATION

ITEM 1. Financial Statements.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)


	Three Months Ended
	March 31,
	2006			2005
				(Restated)
Operating Revenues:
Natural gas sales	$	27,932		$	120,506
Natural gas transportation		195,197			195,258
Natural gas storage		30,155			30,874
Other		6,307			2,307

Total operating revenues		259,591			348,945


Operating Costs and Expenses:
Cost of natural gas sales		27,927			120,506
Cost of natural gas transportation		3,803			4,986
Operation and maintenance		52,725			47,357
Administrative and general		31,912			26,058
Depreciation and amortization		50,899			48,669
Taxes — other than income taxes		13,947			12,247
Other (income) expense, net		(1,477	)		221

Total operating costs and expenses		179,736			260,044


Operating Income		79,855			88,901


Other (Income) and Other Deductions:
Interest expense		15,073			20,120
Interest income — affiliates		(1,944	)		(2,662	)
Allowance for equity and borrowed funds used during construction (AFUDC)		(2,460	)		(1,691	)
Equity in earnings of unconsolidated affiliates		(1,784	)		(1,647	)
Miscellaneous other (income) deductions, net		(2,327	)		(818	)

Total other (income) and other deductions		6,558			13,302


Income before Income Taxes		73,297			75,599

Provision for Income Taxes		27,585			28,459


Net Income	$	45,712		$	47,140

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET (Continued)
(Thousands of Dollars)
(Unaudited)


	March 31,			December 31,
	2006			2005
LIABILITIES AND STOCKHOLDER’S EQUITY

Current Liabilities:
Payables:
Affiliates	$	50,146		$	27,812
Other		87,118			80,876
Transportation and exchange gas payables		31,306			49,657
Accrued liabilities		122,999			168,730
Reserve for rate refunds		7,058			3,763

Total current liabilities		298,627			330,838


Long-Term Debt		1,000,825			1,000,623


Other Long-Term Liabilities:
Deferred income taxes		960,661			955,503
Other		170,930			172,764

Total other long-term liabilities		1,131,591			1,128,267


Contingent liabilities and commitments (Note 3)

Common Stockholder’s Equity:
Common stock $1.00 par value:
100 shares authorized, issued and outstanding		—			—
Premium on capital stock and other paid-in capital		1,652,430			1,652,430
Retained earnings		908,312			902,600
Accumulated other comprehensive loss		(244	)		(408	)

Total common stockholder’s equity		2,560,498			2,554,622


Total liabilities and stockholder’s equity	$	4,991,541		$	5,014,350

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)


	Three Months Ended
	March 31,
	2006			2005
				(Restated)
Cash flows from operating activities:
Net income	$	45,712		$	47,140
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		49,431			49,413
Deferred income taxes		4,633			2,598
Allowance for equity funds used during construction (Equity AFUDC)		(1,799	)		(1,029	)
Changes in current assets and liabilities:
Receivables — affiliates		1,741			(410	)
— others		(15,662	)		(17,618	)
Transportation and exchange gas receivables		2,718			(6,765	)
Inventories		(23,752	)		19,295
Payables — affiliates		22,334			38,867
— others		43,351			3,644
Transportation and exchange gas payables		(18,351	)		(8,855	)
Accrued liabilities		(44,618	)		(45,930	)
Reserve for rate refunds		3,295			(5,007	)
Other, net		(40,919	)		(10,022	)

Net cash provided by operating activities		28,114			65,321


Cash flows from financing activities:
Retirement of long-term debt		—			(200,000	)
Debt issue costs		(5	)		(234	)
Change in cash overdrafts		(19,959	)		(12,126	)
Common stock dividends paid		(40,000	)		(20,000	)

Net cash used in financing activities		(59,964	)		(232,360	)


Cash flows from investing activities:
Property, plant and equipment:
Additions, net of equity AFUDC		(45,021	)		(35,881	)
Changes in accounts payable		(17,150	)		(4,852	)
Advances to affiliates, net		94,429			210,025
Advances to others, net		138			241
Other, net		886			(2,480	)

Net cash provided by investing activities		33,282			167,053


Net increase in cash		1,432			14
Cash at beginning of period		362			176

Cash at end of period	$	1,794		$	190

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

Transcontinental Gas Pipe Line Corporation (Transco) is a wholly-owned subsidiary of Williams Gas Pipeline Company, LLC (WGP). WGP is a wholly-owned subsidiary of The Williams Companies, Inc. (Williams).

In this report, Transco (which includes Transcontinental Gas Pipe Line Corporation and unless the context otherwise requires, all of our subsidiaries) is at times referred to in the first person as “we,” “us” or “our.”

The condensed consolidated financial statements include our accounts and the accounts of our majority-owned subsidiaries. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method.

The condensed consolidated financial statements have been prepared from our books and records. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been condensed or omitted. The condensed unaudited consolidated financial statements include all adjustments both normal recurring and others which, in the opinion of our management, are necessary to present fairly our financial position at March 31, 2006, and results of operations for the three months ended March 31, 2006 and 2005 (restated), and cash flows for the three months ended March 31, 2006 and 2005 (restated). These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2005 Annual Report on Form 10-K.

As a participant in Williams’ cash management program, we have advances to and from Williams. The advances are represented by demand notes. The interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter.

Through an agency agreement, Williams Power Company (WPC), an affiliate, manages our remaining jurisdictional merchant gas sales, which excludes our cash out sales in settlement of gas imbalances. The long-term purchase agreements managed by WPC remain in our name, as do the corresponding sales of such purchased gas. Therefore, we continue to record natural gas sales revenues and the related accounts receivable and cost of natural gas sales and the related accounts payable for the jurisdictional merchant sales that are managed by WPC. WPC receives all margins associated with jurisdictional merchant gas sales business and, as our agent, assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales service has no impact on our operating income or results of operations.

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from

those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) deferred and other income taxes; 6) depreciation; 7) pensions and other post-employment benefits; and 8) asset retirement obligations.

Our Board of Directors declared a cash dividend on common stock in the amount of $40 million on March 31, 2006.

Comprehensive income for the three months ended March 31, 2006 and 2005 (restated) respectively, is as follows (in thousands):


	Three Months
	Ended March 31,
	2006		2005
			(Restated)
Net income	$	45,712	$	47,140
Equity interest in unrealized gain on interest rate hedge, net of tax		164		335

Total comprehensive income	$	45,876	$	47,475

FERC Accounting Guidance On June 30, 2005, the Federal Energy Regulatory Commission (FERC) issued an order, “Accounting for Pipeline Assessment Cost,” to be applied prospectively effective January 1, 2006. The order requires companies to expense certain pipeline integrity-related assessment cost that we have historically capitalized. We anticipate expensing approximately $20 million to $25 million in 2006 that previously would have been capitalized prior to the order becoming effective. During the three months ended March 31, 2006, the application of this order had no material impact on results of operations or financial position.

2. RESTATEMENT

On February 28, 2006, we concluded that our consolidated financial statements for each of the years ending December 31, 2004 and 2003 should be restated to correct an error related to the methodology used to calculate the average cost of our natural gas inventory. We believe the impact of the adjustment is not material to any of the previously issued consolidated financial statements. However, the cumulative adjustment required to correct the error was significant to the Consolidated Statement of Income for 2005.

We revised the weighted average and LIFO cost of our natural gas inventories and valuation of gas imbalances, which corrections thereby affected amounts of previously reported fuel gains, storage losses, and deferred cash out gains and losses. The restatement for these items resulted in an increase in Cost of natural gas transportation of $3.0 million for the three months ended March 31, 2005.

Certain other adjustments were identified in 2005 related to prior periods including an adjustment to lease expense and a correction of depreciation and amortization expense. None of these items were individually significant but they have been reflected in the proper periods in conjunction with the restatement. The impact of these adjustments was an increase in Administrative and general expense of $0.2 million and a decrease in Depreciation and amortization expense of $0.3 million for the three months ended March 31, 2005.

Adjustments for the related income tax effects were also recorded.

The cumulative impact of these adjustments to our Condensed Consolidated Statement of Income for the three months ended March 31, 2005 was a decrease in Operating income of $2.9 million and Net Income of $1.8 million.

The following schedules reconcile the amounts as originally reported in our Condensed Consolidated Statement of Income and Condensed Consolidated Statement of Cash Flows for the three months ended March 31, 2005.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)


	Three Months Ended March 31, 2005
	(As Reported)			Adjustment			(As Restated)
Operating Revenues:
Natural gas sales	$	120,506		$	—		$	120,506
Natural gas transportation		195,258			—			195,258
Natural gas storage		30,874			—			30,874
Other		2,307			—			2,307

Total operating revenues		348,945			—			348,945


Operating Costs and Expenses:
Cost of natural gas sales		120,506			—			120,506
Cost of natural gas transportation		2,021			2,965			4,986
Operation and maintenance		47,357			—			47,357
Administrative and general		25,908			150			26,058
Depreciation and amortization		48,921			(252	)		48,669
Taxes — other than income taxes		12,247			—			12,247
Other (income) expense, net		221			—			221

Total operating costs and expenses		257,181			2,863			260,044


Operating Income		91,764			(2,863	)		88,901


Other (Income) and Other Deductions:
Interest expense		20,120			—			20,120
Interest income – affiliates		(2,662	)		—			(2,662	)
Allowance for equity and borrowed funds used during construction (AFUDC)		(1,691	)		—			(1,691	)
Equity in earnings of unconsolidated affiliates		(1,647	)		—			(1,647	)
Miscellaneous other (income) deductions, net		(818	)		—			(818	)

Total other (income) and other deductions		13,302			—			13,302


Income before Income Taxes		78,462			(2,863	)		75,599

Provision for Income Taxes		29,542			(1,083	)		28,459


Net Income	$	48,920		$	(1,780	)	$	47,140

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)


	Three Months Ended March 31, 2005
	(As Reported)			Adjustment			(As Restated)
Cash flows from operating activities:
Net income	$	48,920		$	(1,780	)	$	47,140
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		49,448			(35	)		49,413
Deferred income taxes		2,598			—			2,598
Allowance for equity funds used during construction (Equity AFUDC)		(1,029	)		—			(1,029	)
Changes in operating assets and liabilities:
Receivables — affiliates		(410	)		—			(410	)
— other		(17,377	)		(241	)		(17,618	)
Transportation and exchange gas receivables		(6,765	)		—			(6,765	)
Inventories		14,961			4,334			19,295
Payables — affiliates		38,867			—			38,867
— other		3,644			—			3,644
Transportation and exchange gas payables		(5,968	)		(2,887	)		(8,855	)
Accrued liabilities		(47,720	)		1,790			(45,930	)
Reserve for rate refunds		(5,007	)		—			(5,007	)
Other, net		(8,753	)		(1,269	)		(10,022	)

Net cash provided by operating activities		65,409			(88	)		65,321


Cash flows from financing activities:
Retirement of long-term debt		(200,000	)		—			(200,000	)
Debt issue costs		(234	)		—			(234	)
Change in cash overdrafts		(12,126	)		—			(12,126	)
Common stock dividends paid		(20,000	)		—			(20,000	)

Net cash used in financing activities		(232,360	)		—			(232,360	)


Cash flows from investing activities:
Property, plant and equipment:
Additions, net of equity AFUDC		(35,728	)		(153	)		(35,881	)
Changes in accounts payable		(4,852	)		—			(4,852	)
Advances to affiliates, net		210,025			—			210,025
Advances to others, net		—			241			241
Other, net		(2,480	)		—			(2,480	)

Net cash provided by investing activities		166,965			88			167,053


Net increase in cash		14			—			14
Cash at beginning of period		176			—			176

Cash at end of period	$	190		$	—		$	190

3. CONTINGENT LIABILITIES AND COMMITMENTS

Rate and Regulatory Matters

General rate case (Docket No. RP01-245) On March 1, 2001, we submitted to the Federal Energy Regulatory Commission (FERC) a general rate filing principally designed to recover costs associated with an increase in rate base resulting from additional plant, an increase in rate of return and related taxes, and an increase in operation and maintenance expenses.

In July 2002, the FERC approved a Stipulation and Agreement (Settlement) which resolved all cost of service, throughput and throughput mix issues in this rate case proceeding with the exception of one cost of service issue related to the valuation of certain right-of-way access for the installation of a fiber optic system by a then Transco affiliate, the resolution of which is to be applied prospectively. The other issues not resolved by the Settlement include various cost allocation, rate design and tariff matters.

On December 3, 2002, an Administrative Law Judge (ALJ) issued his initial decision on the issues not resolved by the Settlement. In the initial decision, the ALJ determined, among other things, that (1) our existing treatment of the arrangement with our former affiliate relating to right of way is just and reasonable, (2) our proposal to roll-in the costs of the Cherokee, Pocono and SunBelt projects is unjust and unreasonable, and (3) our recovery of the costs of the Mobile Bay expansion project on a rolled-in basis is unjust and unreasonable. As to the Mobile Bay issue, the ALJ determined that we had the burden of establishing that roll-in of that project is just and reasonable, but did not address the issue of any potential refunds. Our current rates are based on the roll-in of the Mobile Bay expansion project.

On March 26, 2004, the FERC issued an order that affirmed, in part, and reversed, in part, the ALJ’s initial decision on the issues not resolved by the Settlement. On the issues discussed above, the FERC affirmed the ALJ’s determination that our existing treatment of the arrangement with our former affiliate relating to right of way is just and reasonable and our proposal to roll-in the costs of the Cherokee, Pocono and SunBelt projects is unjust and unreasonable, but reversed the ALJ’s rejection of our proposal to recover the costs of the Mobile Bay expansion project on a rolled-in basis and found that we had shown that our proposed rolled-in rates are just and reasonable. The FERC also affirmed the ALJ’s determination that we must separate our Emergency Eminence Withdrawal service from our Rate Schedule FT service and offer the Emergency Eminence Withdrawal service under a separate rate schedule, thereby permitting shippers to decide whether to take that service. Currently, the cost of the Emergency Eminence Withdrawal service is included as part of our Rate Schedule FT service for those shippers that can access the Eminence Storage Field. Under the FERC’s decision, we would be at risk for those costs to the extent that shippers did not elect to subscribe to all of the separately offered service. On April 26, 2004, several parties, including Transco, filed requests for rehearing of the FERC’s March 26, 2004 order.

On August 5, 2005, the FERC issued an order addressing the requests for rehearing of the March 26, 2004 order. The FERC generally denied rehearing of the March 26, 2004 order, but granted rehearing on a limited number of issues. On the issues described above, the FERC affirmed its determination that we must separate our Emergency Eminence Withdrawal service from our Rate Schedule FT service, but granted rehearing to require that each Rate Schedule FT shipper that currently has access to the Emergency Eminence Withdrawal service must subscribe to its proportionate share of the unbundled Emergency Eminence Withdrawal service until its Rate Schedule FT contract terminates. The FERC also affirmed its determinations that our existing treatment of the arrangement with our former affiliate relating to right of way is just and reasonable, our proposal to roll-in the costs of the Cherokee, Pocono and SunBelt projects is unjust and unreasonable, and

our proposal to recover the costs of the Mobile Bay expansion project on a rolled-in basis is just and reasonable. The August 5, 2005 order did grant rehearing on certain of the cost allocation, rate design and tariff issues, finding, among other things, that we must adopt a “paper” pooling method for our Rate Zone 4, and that we must allocate storage costs to incremental transportation services and to the transportation component of our bundled storage services and include additional storage services in the allocation of storage costs to our transportation services. Pursuant to the Settlement, the changes to our existing practices required by or affirmed in the August 5, 2005 order would be implemented on a prospective basis. On September 6, 2005, several parties, including Transco, filed requests for rehearing of the FERC’s August 5, 2005 order. In addition, the FERC’s orders have been appealed to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court).

Gathering facilities spin-down order (Docket Nos. CP96-206-000 and CP96-207-000) In 1996, we filed an application with the FERC for an order authorizing the abandonment of certain facilities located onshore and offshore in Texas, Louisiana and Mississippi by conveyance to an affiliate, Williams Gas Processing — Gulf Coast Company (Gas Processing). The net book value of these facilities at March 31, 2006, was approximately $298 million. Concurrently, Gas Processing filed a petition for declaratory order requesting a determination that its gathering services and rates be exempt from FERC regulation under the Natural Gas Act of 1938 (NGA). The FERC issued an order dismissing our application and Gas Processing’s petition for declaratory order and in 2001, the FERC issued an order that denied our request for rehearing. Certain parties, including Transco, filed in the D.C. Circuit Court petitions for review of the FERC’s orders and in June 2003, those petitions were denied. Several parties petitioned the United States Supreme Court for review of the D.C. Circuit Court’s opinion, and on January 12, 2004, the Court denied those petitions.

While the proceedings related to the 1996 application were pending, we filed with the FERC the applications described below seeking authorization to abandon portions of the facilities included in the 1996 application.

North Padre Island/Central Texas Systems Spin-down Proceeding (Docket Nos. CP01-32 and CP01-34) In 2000, we filed an application with the FERC seeking authorization to abandon certain of our offshore Texas facilities by conveyance to Gas Processing. Gas Processing filed a contemporaneous request that the FERC declare that the facilities sought to be abandoned would be considered nonjurisdictional gathering facilities upon transfer to Gas Processing. The FERC approved the abandonment and the non-jurisdictional treatment of all of these facilities. Effective December 2001, we transferred to Gas Processing the North Padre Island facilities through a non-cash dividend of $3.3 million, which represents the net book value of the facilities as of that date. Parties filed petitions for review of the FERC’s orders with the D.C. Circuit Court which were consolidated with the appeals of the FERC’s orders in CP96-206 and CP96-207, discussed above, and which were denied by the D.C. Circuit Court in its opinion issued in June, 2003. In 2001, Shell Offshore, Inc. filed a complaint at the FERC against Gas Processing, Williams Field Services Company (WFS) and us alleging concerted actions by these affiliates frustrated the FERC’s regulation of us. The alleged actions are related to offers of gathering service by WFS and its subsidiaries with respect to the North Padre Island facilities. In 2002, the FERC issued an order reasserting jurisdiction over that portion of the North Padre Island facilities previously transferred to WFS. The FERC also determined a gathering rate for service on these facilities, which is to be collected by us. Transco, Gas Processing and WFS each sought rehearing of the FERC’s order, and in May 2003, the FERC denied those requests for rehearing. Transco, Gas Processing and WFS filed petitions for review of the FERC’s orders with the D.C. Circuit Court and on July 13, 2004, the court granted the petitions, vacating the FERC’s orders and remanding the case to the FERC for further proceedings not inconsistent with the court’s opinion. On February 15, 2005, the FERC issued an order in response to the D.C. Circuit Court remand. In that order, the FERC determined that, based

on the record and the court’s decision, there is not a sufficient basis to reassert NGA jurisdiction or to assert Outer Continental Shelf Lands Act jurisdiction over the gathering rates and service on the North Padre Island facilities. Accordingly, the FERC reversed its initial decision, dismissed the complaint filed by Shell, and directed us to remove the North Padre Island gathering rate and rate schedule from our tariff. On March 7, 2005, Shell filed a request for rehearing of the FERC’s February 15, 2005 order. On September 15, 2005, the FERC issued an order denying Shell’s request for rehearing and terminated this Docket No. RP02-99 proceeding, but concurrently with that order instituted a notice of inquiry in Docket No. PL05-10-000 to evaluate possible changes to its test for reassertion of NGA jurisdiction over gathering facilities. If the FERC adopts a different test, the FERC stated that its action in denying Shell’s request for rehearing is without prejudice to Shell’s ability to present evidence that would satisfy that new test. On October 17, 2005, Shell filed a request for rehearing of the FERC’s September 15, 2005 order.

With regard to the approval of the spin-down of the Central Texas facilities, a Transco customer filed a complaint with the FERC in Docket No. RP02-309 seeking the revocation of the FERC’s spin-down approval. In September 2002, the FERC issued an order requiring that, upon transfer of the Central Texas facilities, we acquire capacity on the transferred facilities and provide service to the existing customer under the original terms and conditions of service. Our request for rehearing was denied in May 2003. In that order, the FERC also required that we notify the FERC of Transco’s plans with regard to the transfer of the Central Texas facilities to Gas Processing. We replied that due to the numerous outstanding issues affecting the transfer of those facilities, we could not at that time predict the timing for the implementation of the transfer of the Central Texas facilities. Transco and the customer each also filed a request for rehearing of the FERC’s May 2003 order. On May 6, 2004, the FERC issued an order on rehearing effectively granting the customer’s request for rehearing. On June 7, 2004, we filed a request for rehearing of the May 6, 2004 order, which the FERC denied on July 6, 2004. On July 14, 2004, we filed a petition for review of the FERC’s orders with the D.C. Circuit Court. After we filed our initial brief, the FERC filed a motion for a voluntary remand of the record to permit the FERC to further consider the issues raised and to hold the proceedings in abeyance pending issuance of FERC orders on the matter. On February 11, 2005, the D.C. Circuit Court granted FERC’s motion and remanded the record of this proceeding to the FERC. On June 16, 2005, the FERC issued an order on remand, which, among other things, modifies the remedy adopted in its earlier orders to require Transco to reimburse the customer for any additional costs that it incurs following the transfer of the facilities and seeks to provide further support for its rulings in this proceeding. On July 18, 2005, we filed a request for rehearing of the June 16, 2005 order, which the FERC denied on February 21, 2006. On April 21, 2006, we filed a petition for review of the FERC’s orders in the remand proceeding with the D.C. Circuit Court. While we have not yet transferred any of the facilities authorized for spin down to our affiliate, we continue to evaluate the option of doing so. At March 31, 2006, the net book value of these facilities was $61 million including the Williams purchase price allocation pushed down to Transco.

North High Island/West Cameron Systems and Central Louisiana System Spin-down Proceedings (Docket Nos. CP01-103 and CP01-104, and CP01-368 and CP01-369) In 2001 the FERC issued orders authorizing us to spin down only a portion of these systems to Gas Processing. All legal challenges of these FERC orders have been exhausted and while we have not yet transferred any of the facilities authorized for spin down to our affiliate, we continue to evaluate the option of doing so. On May 6, 2004, the FERC issued an order relating to the Central Louisiana system spin-down proceeding in which the FERC required Transco and Gas Processing to show cause, due to developments in another proceeding, why certain of the Central Louisiana facilities previously found to be gathering should not be classified as jurisdictional transmission facilities. We filed our response to the show cause order on July 6, 2004, arguing that the FERC should not alter its conclusion that the facilities serve a gathering function. On April 19, 2005, the FERC issued an order reversing its earlier finding and found that the facilities in question are jurisdictional transmission

facilities. Transco and Gas Processing filed a request for rehearing of the FERC’s April 19, 2005 order, and on June 28, 2005, the FERC denied that request. On August 26, 2005, Transco and Gas Processing filed a joint petition for review of the FERC’s orders with the D.C. Circuit Court.

The net book value, at the application dates in 2001, of the North High Island/West Cameron and Central Louisiana facilities included in these two applications was approximately $65 million including the Williams purchase price allocation pushed down to Transco.

FERC enforcement matter By order dated March 17, 2003, the FERC approved a settlement between the FERC staff and Williams, WPC and us which resolved certain FERC staff’s allegations. As part of the settlement, WPC agreed, subject to certain exceptions, that it will not enter into new transportation agreements that would increase the transportation capacity it holds on certain affiliated interstate gas pipeline, including Transco. We also agreed to pay a civil penalty in five equal installments, and the remaining two $4 million installments will be paid in 2006 and 2007.

Legal Proceedings.

Royalty claims and litigation In connection with our renegotiations with producers to resolve take-or-pay and other contract claims and to amend gas purchase contracts, we entered into certain settlements which may require that we indemnify producers for claims for additional royalties resulting from such settlements. Through our agent WPC, we continue to purchase gas under contracts which extend, in some cases, through the life of the associated gas reserves. Certain of these contracts contain royalty indemnification provisions, which have no carrying value. We have been made aware of demands on producers for additional royalties and such producers may receive other demands which could result in claims against us pursuant to royalty indemnification provisions. Indemnification for royalties will depend on, among other things, the specific lease provisions between the producer and the lessor and the terms of the agreement between the producer and us. Consequently, the potential maximum future payments under such indemnification provisions cannot be determined. However, we believe that the probability of payments is remote.

A producer had asserted a claim for damages against us for indemnification relating to prior royalty payments. The Louisiana Court of Appeals denied the producer’s appeal and affirmed a lower court’s judgment in our favor. On March 31, 2006, the Louisiana Supreme Court denied the producer’s request for further review. Consequently, we reversed in the first quarter of 2006 a related liability which resulted in an increase to pre-tax income of approximately $7.0 million.

In 1998, the United States Department of Justice (DOJ) informed Williams that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly-owned subsidiaries including us. Mr. Grynberg has also filed claims against approximately 300 other energy companies and alleges that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. The relief sought is an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. In April 1999, the DOJ declined to intervene in any of the Grynberg qui tam cases, including the action filed against the Williams entities in the United States District Court for the District of Colorado. In October 1999, the Panel on Multi-District Litigation transferred all of the Grynberg qui tam cases, including those filed against Williams, to the United States District Court for the District of Wyoming for pre-trial purposes. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims. Grynberg’s measurement claims remain pending

against Williams, including us, and the other defendants, although the defendants have filed a number of motions to dismiss these claims on jurisdictional grounds. Oral argument on these motions occurred on March 17 and 18, 2005. In May 2005, the court-appointed special master entered a report which recommended that many of the cases be dismissed, including the case pending against certain of the Williams defendants, including Transco. The District Court is in the process of considering whether to affirm or reject the special master’s recommendations and heard oral arguments on December 9, 2005.

Hurricanes lawsuits We were named as a defendant in two class action petitions for damages filed in the United States District Court for the Eastern District of Louisiana in September and October 2005 arising from hurricanes that struck Louisiana in 2005. The class plaintiffs, purporting to represent persons, businesses and entities in the State of Louisiana who have suffered damage as a result of the winds and storm surge from the hurricanes, allege that the operating activities of the two sub-classes of defendants, which include all oil and gas pipelines that dredged pipeline canals or installed pipelines in the marshes of south Louisiana (including us) and all oil and gas exploration and production companies which drilled for oil and gas or dredged canals in the marshes of south Louisiana, have altered marshland ecology and caused marshland destruction which otherwise would have averted all or almost all of the destruction and loss of life caused by the hurricanes. Plaintiffs request that the court allow the lawsuits to proceed as class actions and seek legal and equitable relief in an unspecified amount. On April 17, 2006, all defendants, including us, filed a joint motion to dismiss the class action petitions on various grounds.

Environmental Matters

We are subject to extensive federal, state and local environmental laws and regulations which affect our operations related to the construction and operation of pipeline facilities. Appropriate governmental authorities enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. Our use and disposal of hazardous materials are subject to the requirements of the federal Toxic Substances Control Act (TSCA), the federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original act, for release of a “hazardous substance” into the environment. Because these laws and regulations change from time to time, practices that have been acceptable to the industry and to the regulators have to be changed and assessment and monitoring have to be undertaken to determine whether those practices have damaged the environment and whether remediation is required. Since 1989, we have had studies underway to test some of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. We have responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that over the next three years environmental assessment and remediation costs under TSCA, RCRA, CERCLA and comparable state statutes will total approximately $14 million to $16 million, measured on an undiscounted basis. This estimate depends upon a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At March 31, 2006, we had a balance of approximately $14 million for these estimated costs recorded in current liabilities ($4.6 million) and other long-term liabilities ($9.3 million) in the accompanying Condensed Consolidated Balance Sheet.

We consider prudently incurred environmental assessment and remediation costs and costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been

permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs, through future rate filings. Therefore, these estimated costs of environmental assessment and remediation have also been recorded as regulatory assets in Current Assets: Other and Other Assets in the accompanying Consolidated Balance Sheet.

We have used lubricating oils containing polychlorinated biphenyls (PCBs) and, although the use of such oils was discontinued in the 1970s, we have discovered residual PCB contamination in equipment and soils at certain gas compressor station sites. We have worked closely with the EPA and state regulatory authorities regarding PCB issues, and we have a program to assess and remediate such conditions where they exist. In addition, we commenced negotiations with certain environmental authorities and other programs concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. All such costs are included in the $14 million to $16 million range discussed above.

We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $500,000. The estimated remediation costs for all of these sites have been included in the environmental reserve discussed above. Liability under CERCLA (and applicable state law) can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.

We are also subject to the federal Clean Air Act and to the federal Clean Air Act Amendments of 1990 (1990 Amendments), which added significantly to the existing requirements established by the federal Clean Air Act. The 1990 Amendments required that the EPA issue new regulations, mainly related to stationary sources, air toxics, ozone non-attainment areas and acid rain. During the last few years we have been installing new emission control devices required for new or modified facilities in areas designated as non-attainment by EPA. We operate some of our facilities in areas of the country currently designated as non-attainment with the one-hour ozone standard. In April 2004, EPA designated eight-hour ozone non-attainment areas. We also operate facilities in areas of the country now designated as non-attainment with the eight-hour ozone standard. Pursuant to non-attainment area requirements of the 1990 Amendments, and proposed EPA rules designed to mitigate the migration of ground-level ozone (NOx) in 22 eastern states, we are planning installation of air pollution controls on existing sources at certain facilities in order to reduce NOx emissions. We anticipate that additional facilities may be subject to increased controls within five years. For many of these facilities, we are developing more cost effective and innovative compressor engine control designs. Due to the developing nature of federal and state emission regulations, it is not possible to precisely determine the ultimate emission control costs. In March 2004 and June 2004, the EPA promulgated additional regulations regarding hazardous air pollutants; these regulations may impose controls in addition to the controls described above. The emission control additions required to comply with current federal Clean Air Act requirements, the 1990 Amendments, the hazardous air pollutant regulations, and the individual state implementation plans for NOx reductions are estimated to include costs in the range of $40 million to $45 million subsequent to 2005. EPA’s recent designation of new non-attainment areas will result in new federal and state regulatory action that may impact our operations. As a result, the cost of additions to property, plant and equipment is expected to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations, although it is believed that some of those costs are included in the ranges discussed above. Management considers costs associated with compliance with the environmental laws and regulations described above to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

Safety Matters

Pipeline Integrity Regulations We have developed an Integrity Management Plan that meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration final rule pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. In meeting the Integrity Regulations, we have identified the high consequence areas, including a baseline assessment and periodic reassessments to be completed within specified timeframes. Currently, we estimate that the cost to perform required assessments and remediation will be between $275 million and $325 million over the remaining assessment period of 2006 through 2012, a portion of which we began expensing January 1, 2006. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

Summary

Litigation, arbitration, regulatory matters, environmental matters and safety matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, will not have a materially adverse effect upon our future financial position.

Other Commitments

Commitments for construction and gas purchases We have commitments for construction and acquisition of property, plant and equipment of approximately $154 million at March 31, 2006. We have commitments for gas purchases of approximately $266 million at March 31, 2006.

4. DEBT AND FINANCING ARRANGEMENTS

Revolving Credit and Letter of Credit Facilities

Under Williams’ $1.275 billion secured revolving credit facility, letters of credit totaling $115 million, none of which are associated with us, have been issued by the participating institutions and no revolving credit loans were outstanding at March 31, 2006.

In May 2006, the $1.275 billion secured revolving credit facility was replaced with a $1.5 billion unsecured revolving credit facility. The new facility contains similar terms and covenants as the secured facility.

Issuance of Long-Term Debt

On April 11, 2006, we issued $200 million of notes which pay interest at 6.4% per annum on April 15 and October 15 each year, beginning October 15, 2006 (6.4% Notes). The 6.4% Notes mature on April 15, 2016, but are subject to redemption at any time, at our option, in whole or part, at a specified redemption price, plus accrued and unpaid interest to the date of redemption. The net proceeds of the sale will be used for general corporate purposes, including the funding of capital expenditures.

5. STOCK-BASED COMPENSATION

Plan Information

The Williams Companies, Inc. 2002 Incentive Plan (Plan) was approved by stockholders on May 16, 2002, and amended and restated on May 15, 2003, and January 23, 2004. The Plan provides for common-stock-based awards to both employees and nonmanagement directors. Upon approval by the stockholders, all prior stock plans were terminated resulting in no further grants being made from those plans. However, awards outstanding in those prior plans remain in those plans with their respective terms and provisions.

The Plan permits the granting of various types of awards including, but not limited to, stock options and deferred stock. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved.

Accounting for Stock-Based Compensation

Prior to January 1, 2006, we accounted for the Plan under the recognition and measurement provisions of Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations, as permitted by Financial Accounting Standards Board (FASB) Statement No. 123, Accounting for Stock-Based Compensation (SFAS No. 123). Compensation cost was not recognized in the Consolidated Statement of Income for the three months ending March 31, 2005, as all options granted under the Plan had an exercise price equal to the market value of the underlying common stock on the date of the grant. Prior to January 1, 2006, compensation cost was recognized for deferred share awards. Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS No. 123(R), using the modified-prospective method. Under this method, compensation cost recognized in the first quarter of 2006 includes: (1) compensation cost for all share-based payments granted through December 31, 2005, but for which the requisite service period had not been completed as of December 31, 2005, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (2) compensation cost for all share-based payments granted subsequent to December 31, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123(R). Results for prior periods have not been restated. Total stock-based compensation expense for the first quarter of 2006 was $0.3 million excluding amounts included in allocations from Williams and WGP, included in administrative and general expenses. Measured but unrecognized stock-based compensation expense at March 31, 2006, was $7.9 million, which is comprised of approximately $3.4 million related to stock options and approximately $4.5 million related to deferred shares. These amounts are expected to be recognized over a weighted average period of 2.2 years.

The following table illustrates the effect on net income if we had applied the fair value recognition provisions to SFAS No. 123 to options granted under the Plan for the quarter ending March 31, 2005. For purposes of this pro forma disclosure, the value of the options was estimated using a Black-Scholes option pricing model and amortized to expense over the vesting period of the options.


	Three months
	Ended
	March 31, 2005
	(thousands)
Net income, as restated	$	47,140
Add: Stock-based employee compensation included in the Condensed Consolidated Statement of Income, net of related tax effects		97

Deduct: Stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(400	)

Pro forma net income, as restated	$	46,837

Stock Options

Stock options are valued at the date of award and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after grant.

The following summary reflects stock option activity and related information for the quarter ending March 31, 2006.


				Weighted
				Average		Aggregate
				Exercise		Intrinsic
	Options			Price		Value
	( Thousands )					(Millions)
Outstanding at December 31, 2005		3,394		$	16.56
Granted		98		$	21.67
Exercised		(173	)	$	13.52	$	1.5

Cancelled		(9	)	$	32.53
Employee transfers, net		(68	)	$	—

Outstanding at March 31, 2006		3,242		$	17.09	$	26.9

Exercisable March 31, 2006		2,626		$	17.20	$	23.3

The following summary provides additional information about stock options that are outstanding and exercisable at March 31, 2006 (option in thousands).


	Stock Options Outstanding								Stock Options Exercisable
					Weighted						Weight
			Weighted		Average				Weighted		Average
			Average		Remaining				Average		Remaining
			Exercise		Contractual				Exercise		Contractual
	Options		Price		Life		Options		Price		Life
Range of Exercise Prices	(Thousands)				(Years)						(Years)
$2.27 to $10.00		1,573	$	7.30		6.1		1,374	$	6.92		5.9
$14.80 to $15.89		212	$	15.68		2.9		212	$	15.68		2.9
$19.29 to $31.56		900	$	21.78		6.4		483	$	23.45		4.0
$34.54 to $42.29		557	$	37.74		2.0		557	$	37.74		2.0

Total		3,242	$	17.09		5.3		2,626	$	17.20		4.5

The estimated weighted average grant-date fair value of stock options granted in the first quarter of 2006 is $8.37. The Black-Scholes option pricing model was used to estimate the grant-date fair value of each stock option granted. The fair values of options granted during the first quarter of 2006 were estimated using the following assumptions:


Assumptions:
Expected dividend yield	1.4	%
Expected volatility	36.3	%
Risk-free interest rate	4.63	%
Expected life (years)	6.5

The expected dividend yield is based on the average annual dividend yield as of the grant date. Expected volatility is based on the historical volatility in our stock and the implied volatility on traded options. In calculating historical volatility, returns during calendar year 2002 were excluded as the extreme volatility during that time is not reasonably expected to be repeated in the future. The risk-free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life of the option is based on historical exercise behavior and expected future experience.

Deferred Shares

Deferred shares are valued at market value on the grant date of the award and generally vest over three years. Deferred share expense, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.

The following summary reflects nonvested deferred share activity and related information for the quarter ending March 31, 2006.


				Weighted
				Average
				Grant-
				Date
				Fair
Deferred Shares	Shares			Value

Nonvested at December 31, 2005		180,722		$	14.68
Granted		129,205		$	21.67
Vested		(34,500	)	$	9.93
Forfeited		(330	)	$	21.67

Nonvested at March 31, 2006		275,097		$	18.55

The total market value of shares issued during the quarter was approximately $0.8 million.

Performance-based share awards issued under the Plan represent 43 percent of nonvested deferred shares outstanding at March 31, 2006. These awards are earned at the end of a three-year period based on actual performance against a performance target. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original award amount.

ITEM 2. Management’s Narrative Analysis of Results of Operations.

General

The following discussion should be read in conjunction with the consolidated financial statements, notes and management’s narrative analysis contained in Items 7 and 8 of our 2005 Annual Report on Form 10-K and with the condensed consolidated financial statements and notes contained in this report.

Restatement of Financial Results

We have accordingly restated the condensed consolidated statements of income and cash flows for the three months ending March 31, 2005. See “Item 1. Financial Statements” in this Form 10-Q.

For a discussion of additional information on the restatement, see “Item 1. Financial Statements – Notes to Condensed Consolidated Financial Statements – 2. Restatement.”

RESULTS OF OPERATIONS

Operating Income and Net Income

Our operating income for the three months ended March 31, 2006 was $79.9 million compared to operating income of $88.9 million for the three months ended March 31, 2005. Net income for the three months ended March 31, 2006 was $45.7 million compared to $47.1 million for the three months ended March 31, 2005. The lower operating income of $9.0 million was due primarily to increases in operation and maintenance expenses, administrative and general expenses, depreciation and amortization expenses, and taxes other than income taxes, partially offset by an increase in other revenues and a decrease in other expenses as discussed below. The decrease in net income of $1.4 million was mostly attributable to the lower operating income, partially offset by a decrease in interest expense as discussed below.

Transportation Revenues

Our operating revenues related to transportation services for the three months ended March 31, 2006 of $195.2 million were comparable to the revenues of $195.3 million for the three months ended March 31, 2005.

As shown in the table below, our total market-area deliveries for the three months ended March 31, 2006 decreased 33.9 trillion British Thermal Units (TBtu) (7.1%) when compared to the same period in 2005. The decreased deliveries are primarily the result of a milder winter season. Our production area deliveries for the three months ended March 31, 2006 were comparable to the same period in 2005.


	Three months
	Ended March 31,
Transco System Deliveries (TBtu)	2006		2005
Market-area deliveries:
Long-haul transportation		197.5		209.8
Market-area transportation		245.9		267.5

Total market-area deliveries		443.4		477.3
Production-area transportation		59.4		60.4

Total system deliveries		502.8		537.7


Average Daily Transportation Volumes (Tbtu)		5.6		6.0
Average Daily Firm Reserved Capacity (Tbtu)		7.0		6.9

Our facilities are divided into eight rate zones. Five are located in the production area and three are located in the market area. Long-haul transportation is gas that is received in one of the production-area zones and delivered in a market-area zone. Market-area transportation is gas that is both received and delivered within market-area zones. Production-area transportation is gas that is both received and delivered within production-area zones.

Sales Revenues

We make jurisdictional merchant gas sales pursuant to a blanket sales certificate issued by the FERC, with most of those sales previously having been made through a Firm Sales (FS) program which gave customers the option to purchase daily quantities of gas from us at market-responsive prices in exchange for a demand charge payment. Pursuant to the terms of an agreement with the FERC which resolved a prior investigation, we terminated our remaining FS agreements effective April 1, 2005.

Through an agency agreement, WPC manages our remaining jurisdictional merchant gas sales, which excludes our cash out sales in settlement of gas imbalances. The long-term purchase agreements managed by WPC remain in our name, as do the corresponding sales of such purchased gas. Therefore, we continue to record natural gas sales revenues and the related accounts receivable and cost of natural gas sales and the related accounts payable for the jurisdictional merchant sales that are managed by WPC. WPC receives all margins associated with jurisdictional merchant gas sales business and, as our agent, assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales service and the termination of the FS agreements in April 2005 have no impact on our operating income or results of operations.

In addition to our merchant gas sales, we also have cash out sales, which settle gas imbalances with shippers. In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on our behalf than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables. Our tariff includes a method whereby the majority of transportation imbalances generated after August 1, 1991 are settled on a monthly basis through cash out sales or purchases. The cash out sales have no impact on our operating income or results of operations.

Operating revenues related to our sales services were $27.9 million for the three months ended March 31, 2006, compared to $120.5 million for the same period in 2005. The decrease was primarily due to a lower volume of merchant sales because of the termination of the FS agreements during 2005.


	Three months
	Ended March 31,
Gas Sales Volumes (TBtu)	2006		2005
Long-term sales		—		7.8
Short-term sales		0.6		2.7

Total gas sales		0.6		10.5

Storage Revenues

Our operating revenues related to storage services of $30.2 million for the three months ended March 31, 2006 were comparable to the revenues of $30.9 million for the same period in 2005.

Other Revenues

Our other operating revenues were $6.3 million for the three months ended March 31, 2006 compared to $2.3 million for the same period in 2005. The increase was primarily due to higher environmental mitigation credit sales.

Operating Costs and Expenses

Excluding the cost of natural gas sales of $27.9 million for the three months ended March 31, 2006 and $120.5 million for the comparable period in 2005, our operating expenses for the three months ended March 31, 2006, were approximately $12.3 million higher than the comparable period in 2005. This increase was primarily attributable to higher operation and maintenance expenses, administrative and general expenses, depreciation and amortization expense and taxes other than income taxes, partially offset by lower other expenses. The increase in operation and maintenance expense in 2006 of $5.4 million is due primarily to higher material and supplies expenses of $2.2 million, contract services of $1.4 million and platform space rentals of $0.7 million. The increase in administrative and general expense of $5.9 million is mostly due to higher reimbursable costs associated with post-retirement costs other than pensions of $2.3 million, higher group insurance expense of $2.0 million and an increase of $1.1 million of allocated corporate expenses. The increase in depreciation and amortization of $2.2 million was primarily due to the development costs related to the environmental mitigation credit sales discussed above. The increase in taxes other than income taxes of $1.7 million is primarily due to higher property taxes resulting from increased property values and additional capital spending. The lower other operating costs and expenses were primarily due to a $2.0 million reduction of accrued liabilities for royalty claims associated with certain producer indemnities. See “Item 1. Financial Statements – Notes to Condensed Consolidated Financial Statements -3. Contingent Liabilities and Commitments.”

Other Income and Other Deductions

Other income and other deductions for the three months ended March 31, 2006 resulted in lower net expense of $6.7 million compared to the same period in 2005. This was primarily due to a $5.0 million decrease in interest expense resulting from the reduction of accrued liabilities for royalty claims associated with certain producer indemnities. See “Item 1. Financial Statements – Notes to Condensed Consolidated Financial Statements -3. Contingent Liabilities and Commitments.”

Method of Financing

for general corporate purposes, including the funding of capital expenditures.

Capital Expenditures

As shown in the table below, our capital expenditures for the three months ended March 31, 2006 were $62.2 million, compared to $40.7 million for the three months ended March 31, 2005.


	Three months
	Ended March 31,
	2006		2005
	(In Millions)
Capital Expenditures			(Restated)
Market-area projects	$	1.5	$	2.6
Supply-area projects		29.5		3.7
Maintenance of existing facilities and other projects		31.2		34.4

Total capital expenditures	$	62.2	$	40.7

Our capital expenditures estimate for 2006 and future capital projects are discussed in our 2005 Annual Report on Form 10-K. The following describes those projects and any new capital projects proposed by us.

Leidy to Long Island Expansion Project The Leidy to Long Island Expansion Project will involve an expansion of our existing natural gas transmission system in Zone 6 from the Leidy Hub in Pennsylvania to Long Island, New York. The project will provide 100,000 dekatherms per day (dt/d) of incremental firm transportation capacity, which has been fully subscribed by one shipper for a twenty-year primary term. The project facilities will include pipeline looping in Pennsylvania and pipeline looping, uprating and replacement and a natural gas compressor facility in New Jersey. The estimated capital cost of the project is approximately $121 million. We expect that over three-quarters of the project expenditures will occur in 2007. We filed an application for FERC approval of the project in December 2005. The target in-service date for the project is November 1, 2007.

Potomac Expansion Project We held an “open season” from July 19 through August 17, 2005 to receive requests from potential shippers for new firm transportation capacity to be made available on the Transco pipeline system from receipt points in North Carolina to delivery points in the greater Washington, D.C. metropolitan area under our proposed Potomac Expansion Project. As a result of the open season, the expansion is being designed to create 165,000 dt/d of incremental firm transportation capacity, which has been fully subscribed by shippers under long-term firm arrangements. The estimated capital cost of the project is approximately $73 million. We filed a request for pre-filing review with the FERC on November 10, 2005. The FERC granted the request on November 17, 2005. We plan to file a certificate application for FERC approval of the project during the third quarter of 2006. The target in-service date for the project is November 1, 2007.

Sentinel Expansion Project We held an open season from October 31, 2005 through December 2, 2005 to receive requests from potential shippers for new firm transportation capacity to be made available on the Transco pipeline system under our proposed Sentinel Expansion Project. During the open season we received requests for a total of 256,000 dt/d of incremental firm transportation capacity from the Leidy Hub in Clinton County, Pennsylvania and/or the Pleasant Valley Interconnection with Cove Point LNG, LP in Fairfax County, Virginia to various delivery points requested by the shippers. We are evaluating the facilities required to support such requested capacity. The final project size, location of facilities and capital cost will depend on the outcome of that evaluation and the level of firm market commitment confirmed with the

requesting parties. The proposed in-service date for the project is November 1, 2008.

ITEM 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (Disclosure Controls) was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Senior Vice President and our Vice President and Treasurer. Based upon that evaluation, our Senior Vice President and our Vice President and Treasurer have concluded that our Disclosure Controls and procedures were effective at a reasonable assurance level.

Our management, including our Senior Vice President and our Vice President and Treasurer, does not expect that our Disclosure Controls or our internal controls over financial reporting (Internal Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and the Internal Controls will be modified as systems change and conditions warrant.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

In the first quarter of 2006 and as reported in our 2005 Annual Report on Form 10-K, we identified a material weakness in internal control over financial reporting associated with our inventory valuation accounting for the period June 2000 to December 2005. Specifically, the material weakness related to the calculation of the weighted average cost of our natural gas inventory, which affected the calculation of fuel gains and losses, storage losses, and deferred cash-out gains and losses during that period. In the first quarter of 2006, we remediated this material weakness and restated our consolidated financial statements for each of the two years in the period ending December 31, 2004, and retained earnings at January 1, 2003 to reflect the correction of our inventory valuation accounting.

During the fourth quarter of 2005 and as reported in our 2005 Annual Report on Form 10-K, we also identified a material weakness in internal control over financial reporting associated with the absence of an effective control to identify to specific customers a material amount of transportation and exchange

imbalance volumes, primarily for the period April 2003 to December 2004. These natural gas volumes represent gas received in excess of amounts delivered on our pipeline systems that have not yet been associated with specific transportation contracts and related customers, and are recorded within Transportation and Exchange Gas Payables in our consolidated balance sheet. In 2005, we implemented controls designed to prevent the repetition of this failure of identification in future periods. In 2006, we will be performing analyses of historical data pertaining to transportation and exchange imbalance volumes and developing new system reporting tools that will assist us in identifying the natural gas volumes relative to 2003 and 2004 to specific transportation contracts and related customers.

Changes in Internal Control over Financial Reporting

Other than the changes in accounting with respect to the valuation for natural gas system inventory discussed above, there have been no changes in our internal control during the first quarter of 2006 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II — OTHER INFORMATION

ITEMS 1. LEGAL PROCEEDINGS.

See discussion in Note 3 of the Notes to Condensed Consolidated Financial Statements included herein.

ITEM 1A. RISK FACTORS.

There are no material changes to the Risk Factors previously disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2005.

ITEM 5. OTHER INFORMATION.

On May 1, 2006, the Company entered into a Credit Agreement among the Company, Williams, Northwest Pipeline Corporation, and Williams Partners L.P. (collectively, the “Borrowers”), the lenders from time to time parties thereto, and Citibank, N.A., as administrative agent (the “Credit Agreement”).

The Credit Agreement replaces the Amended and Restated Credit Agreement, dated May 20, 2005, by and among the Borrowers, the several lenders from time to time parties thereto, and Citicorp USA, Inc., as administrative agent and collateral agent (the “Old Credit Agreement”).

The Credit Agreement consists of a $1.5 billion senior unsecured revolving line of credit. The Credit Agreement has a term of three years. Borrowings under the Credit Agreement bear interest at a variable interest rate based on either LIBOR or a base rate, in either case plus an applicable margin that varies depending upon the rating of the applicable borrower’s senior unsecured long-term debt.

The Credit Agreement is guaranteed by Williams Gas Pipeline Company, LLC. The obligations of Williams Partners L.P. are guaranteed by Williams.

The Credit Agreement contains a number of restrictions on the Borrowers’ business, including, but not limited to, restrictions on certain of the Borrowers’ and certain of the Borrowers’ subsidiaries’ ability to grant liens on assets, merge, consolidate, or sell assets; incur indebtedness; engage in transactions with related parties; and make distributions on equity interests. In addition, Williams is at certain times subject to a minimum ratio of consolidated EBITDA to interest expense financial maintenance covenant. The Credit Agreement also contains affirmative covenants and events of default, including a cross acceleration to debt in a principal amount of $100 million or greater, and the occurrence of a change of control. Failure to comply with these covenants, or the occurrence of an event of default, could result in acceleration of the Borrowers’ debt and other financial obligations under the Credit Agreement.

As of May 1, 2006, there are no outstanding borrowings under the Credit Agreement.

ITEM 6. EXHIBITS

The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith.

(4)

Instruments defining the rights of Security holders, including indentures

Indenture dated April 11, 2006 between Transco and JP Morgan Chase Bank, N.A., as trustee (Exhibit 4.1 to Transco Form 8-K filed April 11, 2006).

(10)

Material contracts

-	1	Registration Rights Agreement dated April 11, 2006 between Transco, Banc of America Securities LLC, Greenwich Capital Markets, Inc. and other parties listed therein, as Initial Purchasers ( Exhibit 10.1 to Transco Form 8-K filed April 11, 2006).

-	2	Credit Agreement, dated May 1, 2006, among The Williams Companies, Inc., Northwest Pipeline Corporation Transcontinental Gas Pipe Line Corporation, and Williams Partners L.P., as Borrowers, and Citibank, N.A., as Administrative Agent (Exhibit 10.1 to The Williams Companies, Inc. Form 8-K filed May 1, 2006 Commission File Number 1-4174).

(31)

Section 302 Certifications

-	1	Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

-	2	Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32)

Section 906 Certification

Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


	March 31,		December 31,
	2006		2005
ASSETS
Current Assets:
Cash	$	1,794	$	362
Receivables:
Affiliates		2,633		4,374
Advances to affiliates		35,878		130,307
Others, less allowance of $397 ($509 in 2005)		100,400		93,827
Transportation and exchange gas receivables		7,188		9,906
Inventories		106,432		82,680
Deferred income taxes		15,700		15,283
Other		49,972		17,663

Total current assets		319,997		354,402


Investments, at cost plus equity in undistributed earnings		44,115		44,108


Property, Plant and Equipment:
Natural gas transmission plant		6,177,274		6,134,951
Less-Accumulated depreciation and amortization		1,813,459		1,776,946

Total property, plant and equipment, net		4,363,815		4,358,005


Other Assets		263,614		257,835


Total assets	$	4,991,541	$	5,014,350


		TRANSCONTINENTAL GAS PIPE LINE CORPORATION (Registrant)

Dated: May 5, 2006		By /s/ Jeffrey P. Heinrichs
		Jeffrey P. Heinrichs
		Controller
		(Principal Accounting Officer)

	a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	c)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the period covered by the report that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


By:		/s/ Phillip D. Wright
		Phillip D. Wright
		Senior Vice President
		(Principal Executive Officer)

	a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	c)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the period covered by the report that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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1.		I have reviewed this quarterly report on Form 10-Q of Transcontinental Gas Pipe Line Corporation;

2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.		The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)), for the registrant and have:

	a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


By:		/s/ Richard D. Rodekohr Richard D. Rodekohr
		Vice President and Treasurer
		(Principal Financial Officer)


/s/ Phillip D. Wright Phillip D. Wright
Senior Vice President
May 5, 2006

/s/ Richard D. Rodekohr Richard D. Rodekohr
Vice President and Treasurer
May 5, 2006